THE INCOME METHOD can be calculated in more than one way to value a project.
The Minnesota Tax Court chose a method that looked back in time rather than at projected earnings.
Minnesota Energy Resources Corporation is a local gas distribution company in Minnesota. It owns 3,611 miles of transmission and distribution lines. Property tax assessments of real property are handled by each county, but personal property — equipment — is assessed by the state.
The state assessed the company’s gas lines at $118.2 million in 2008 rising to $161.5 million by 2012. The company challenged the assessments. An appraiser hired by it said the state overvalued the gas lines, and the correct figures should have been $51.5 million in 2008 rising to $120.5 million by 2012. An expert hired by the state put the values even higher than the state assessments: $200 million rising to $297.9 million.
The Tax Court decided the correct 2008 value was in between the state assessment and the gas company figure, but it put the 2012 value above the state assessment. Its final figures were $94.7 million in 2008 rising to $174.7 million in 2012.
The court looked at the three standard methods for valuing equipment: depreciated replacement cost, comparable sales and the income method. It said there was not enough data publicly available about recent sales of similar assets or companies to use the comparable sales method.
It calculated the depreciated replacement cost, or the cost to build new gas lines, and then adjusted the amount for the age of the gas lines in question.
Turning to the income method, it said it was more comfortable relying on historic revenue rather than what the company was projecting it would earn in the future because the company had been consistently wrong in its earnings projections. It then used two approaches to distill the numbers to a market value.
Under one approach — the “direct capitalization method” — it divided the company’s net operating income for the year in question — for example, the 2008 net operating income — by a “capitalization rate” that is the weighted average cost of equity and debt for a comparable company.
It used 7.51% as the capitalization rate in 2008 falling to 5.87% in 2012. It subtracted 5% of the prior year’s revenue as the value of working capital and 5% of business enterprise value as the value of intangible assets, neither of which is subject to property taxes.
The other way to calculate value under the income method is to discount projected cash flow.
However, the court rejected that approach due to its lack of confidence in the gas company’s revenue projections, which it said experience has shown are 30% to 35% overstated. It did not believe that a potential purchaser would rely on the company’s forecasts.
In the end, the court assigned 80% weight to the income method and 20% weight to the depreciated replacement cost approach. One of the experts argued that the cost approach is less reliable than the income method because it does not measure the market value of a group of assets when they are used in combination with one another.
The case is Minnesota Energy Resources Corporation v. Commissioner of Revenue. The court released its decision on September 29.
AN IRS BUSINESS PLAN showing what guidance the US tax agency plans to issue by next June lists several items of interest to the project finance community.
The plan was released in late August. The Internal Revenue Service said it hopes to issue “regulations on prepaid forward contracts.”
This could affect the pattern in which income must be reported under prepaid power purchase agreements.
In January 2008, the agency issued a revenue ruling analyzing the tax treatment for a forward contract to buy euros. The holder paid $100 on January 1, 2007, at a time when $100 was worth €75, for a contract requiring delivery of €75 plus a return three years later on January 1, 2010. The forward contract paid the holder the dollar equivalent of €75 plus a compound stated rate of return, with conversion into dollars occurring at the exchange rate on January 1, 2010. The IRS said the instrument was in substance a eurodenominated loan by the holder to the issuer. The IRS said in a separate notice the same day that it is studying the tax treatment of prepaid forward contracts, and it asked for comments on a list of questions, including whether the seller under a prepaid forward contract that is in fact a forward sale, rather than a loan, should be required to accrue income during the term of the forward contract and, if so, how the amount of income each year should be calculated.
The IRS said in the new business plan that it will issue “guidance on the energy credit under section 48.” Jaime Park, chief of the IRS branch that handles energy credits, said the guidance will address performance and quality standards for small wind turbines.
The IRS said it will issue “guidance under section 7704(d)(1)(E) regarding qualifying income for publicly traded partnerships.” This is a placeholder for guidance about master limited partnerships or MLPs. (See the March 2006 NewsWire starting on page 1 for a survey article about MLPs.)
The IRS has had a hold since February 2014 on private letter rulings about whether some businesses can be organized as MLPs. There is a great deal of interest in the market about whether paper and packaging companies can put part of their businesses in MLPs, thus avoiding a corporate-level tax on earnings from the businesses. The hold does not appear to have affected rulings in this area.
An “integrally related” or “hamburger stand” issue is holding up some other rulings. The boom in US oil and gas production has led to a string of private letter ruling requests about whether companies that provide services to oil and gas producers can organize as MLPs. The key to qualifying as an MLP is to have at least 90% of the gross income the MLP earns each year be from passive sources — like interest and dividends— or from “exploration, development, mining or production, processing, refining or transportation . . . or the marketing of any mineral or natural resource.” A company engaged directly oil or gas production qualifies.
Does a company providing services to an oil or gas producer qualify? For example, would a hamburger stand set up next to a gas field to feed workers involved in gas production qualify? The IRS has been issuing private rulings that allow income from some such services to be treated as good income for an MLP. It put a hold on further rulings while it figures out where to draw the line.
Curt Wilson, the IRS associate chief counsel with responsibility for the area, said at an oil and gas conference in New York in early November that the IRS has some “tentative ideas about where we are headed” on a standard that would allow the agency to lift the IRS rulings freeze. “The next step for us to do is to put that on paper and then circulate that paper and get buy-in from all the people who have a say in this.” He said he would like to reopen the rulings window once there is internal agreement on concepts without waiting for formal guidance. He said rulings are still being issued as long as they do not raise the integrally related issue.
The IRS also hopes to issue guidance on whether property held simultaneously for sale and lease can be depreciated. Equipment that a company holds for sale is considered inventory. The company cannot normally place such property in service or depreciate it. Equipment that a leasing company holds out for lease is in service and can be depreciated.
The agency hopes to issue “regulations under section 267 regarding the application of § 1.267(b)-1(b) to partners and partnerships.” Many renewable energy projects are owned by partnerships. The partnerships usually show tax losses due to depreciation for the first several years. US tax rules prevent the partnership from claiming net losses if electricity from the project is sold to a related party. A taxpayer cannot sell to an affiliate and claim a loss on the sale. As a consequence, most tax equity partnership documents make the partners covenant that they will not be related to the offtaker for the electricity. Denial of loss deductions when there are related-party sales occurs mainly through IRS regulations under section 707(b) of the US tax code. Any new regulations that the IRS issues under section 267 to deal with losses in a partnership setting will be read with interest by tax counsel for any possible application to renewable energy deals.
Finally, the agency hopes to issue regulations to address how gain should be reported in sales where part of the purchase price is contingent on future events.
TREASURY CASH GRANTS have moved into a litigation phase.
There are 20 pending lawsuits against the US Treasury by companies that feel the Treasury paid smaller cash grants on renewable energy projects than they were entitled to receive. Many renewable energy projects placed in service between 2009 and 2013 had the option of being paid 30% of the cost of the project in cash by the Treasury in lieu of taking federal tax credits. Some solar projects still retain that option if they are completed by December 2016. The payments are made under section 1603 of the American Recovery and Reinvestment Tax Act.
Twenty-two lawsuits in total have been filed against Treasury, but the taxpayers withdrew two after the Treasury filed counterclaims accusing the companies of fraud.
All the suits have been filed in the US Court of Federal Claims. The oldest pending suit was filed in July 2012. Companies have six years after a grant is paid to decide whether to litigate.
Some taxpayers have asked the court to decide their cases at “summary judgment,” meaning they feel there is no disagreement about the facts and the judge should decide the cases based on legal briefs filed by each side. The government has opposed some summary judgment motions on grounds that it needs to do more discovery to establish the facts, but filed its own motion for summary judgment in others.
Meanwhile, a US Claims Court judge ordered the Treasury in October in a case involving a solar rooftop company to disclose the benchmarks it used from the start of the program to pay grants on rooftop systems and to disclose limited information about how it dealt with the company’s applications. However, the judge declined to compel disclosure of other information, including what the Treasury paid on comparable applications, or information about how it developed its general screening policies or the lower benchmarks it used to make payments than the amounts for which the company applied. Discovery in the case is now scheduled to run into early August 2015, making a decision in the case unlikely before 2016.
The earliest decision in any of the pending lawsuits could come in early 2015 in a case involving a biomass project that the Treasury says qualified for only a partial grant because it produced both steam and electricity and only the part of the project related to electricity generation qualified for a grant. (For earlier coverage of the biomass case, see the February 2013 NewsWire starting on page 27.) The court is scheduled to hear arguments in the case starting on December 15.
In other developments, the Treasury said in October that grants approved for payment between October 1, 2014 and September 30, 2015 will be subject a haircut of 7.3% due to budget sequestration. The figure was 7.2% for grants approved for payment in fiscal year 2014. Sequestration will continue through fiscal year 2021 unless rescinded by Congress.
A technical corrections bill awaiting action in the “lame duck” session of Congress would clarify that Treasury cash grants do not have to be reported as income by companies paying taxes under the alternative minimum tax. The American Recovery and Reinvestment Tax Act made clear that the grants are not income for regular income tax purposes. However, Congress failed to say anything at the time about the alternative minimum tax. US corporations must compute their taxes under the regular corporate income tax and the minimum tax and pay essentially whichever tax is greater. The technical correction has been waiting for Congressional action since 2010.
The IRS has given up waiting and feels it must enforce the law aswritten until the technical correction is enacted. The correction would be retroactive as if included in the original statute.
REITS continue to draw attention.
The comprehensive corporate tax reform bill that Dave Camp (R-Michigan), the outgoing chairman of the House tax-writing committee, released as a discussion draft in February would effectively return real estate investment trusts to their roots as vehicles for investors to pool capital to invest in office and apartment buildings and other real property, but rule out their use to own cell towers, billboards, transmission lines and similar business assets.
A REIT must hold at least 75% “real property” or mortgages on real property. It can also hold some assets through a taxable subsidiary that do not qualify for be held by the REIT directly. The Camp bill would defined “real property” for REIT purposes to exclude assets with shorter depreciable lives than 27.5 years.
Harold Hancock, a tax counsel to the House tax-writing committee, told a DC Bar tax section meeting in late October, “A number of [businesses were] engaging in spinoffs that were not started as a vehicle for everyday investors to invest in real estate but instead were actual operating companies that figured out a way to put real estate into a REIT and then have the actual business operations be conducted in a [taxable REIT subsidiary]. We don’t like these types of transactions.”
The Camp bill is expected to serve as a starting point for drafting if the next Congress decides to take up corporate tax reform.
Hancock said timber is not treated as real property under the draft because the committee staff believes timber should be treated as inventory.
He said the staff has discussed the issue at length with the timber industry, and he expects the discussions will continue.
Meanwhile, Martin Sullivan, an economist who writes for Tax Notes magazine, estimated in September that 20 corporations that have spun off timber, casinos, data centers, prisons, cell towers and billboards recently into REITs or have announced an intention to do so, will save $900 million to $2.2 billion a year in corporate income taxes, assuming their earnings remain at 2014 levels. Sullivan said the estimates overstate the revenue loss to the government because they fail to take into account larger tax payments by the REIT shareholders, many of whom are individuals. REITs must distribute at least 90% of their income each year. Life Time Fitness Inc., which owns health clubs, saw its stock shoot up 15% immediately after it announced an intention to convert into a REIT in late August. Sullivan said, “Expect announcements like this to continue” when a company can increase its market capitalization by $250 million “in a matter of minutes.”
REIT conversions can be expensive.
Iron Mountain, a data center company that spun off assets into a REIT as of January 1, 2014, said in its latest financial statements that it expects to have spent $145 to $155 million on legal fees, tax work, advisory fees and similar costs to convert over the period 2012 through 2014, plus another $40 to $45 million in capital costs such as reprogramming information systems to operate as a REIT, plus another $15 million a year on REIT compliance.
Equinix, a data center company, estimates its costs will run to $84 million over the same period, plus $5 to $10 million in annual compliance costs. Penn National, a casino company that converted in 2013, estimated its cost to convert was $125 million. “I can’t overemphasize the complexity,” the CEO said.
INDIA lost a round in court over whether taxes can be triggered when a foreign parent company makes a capital contribution to its Indian subsidiary in exchange for shares.
The Bombay High Court said no in October in a case involving Vodafone.
India has been asserting the right to tax multinational corporations that make capital contributions in exchange for shares in Indian subsidiaries to the extent the shares are worth more when issued than the contributed capital.
The tax authorities claimed that share issuances by Vodafone India Services to its offshore parent in August 2008 led to income in the next two years.
Vodafone subscribed to 289,244 shares in Vodafone India for 8,000 rupees a share that the Indian authorities said were worth 50,000 rupees a share. Indian authorities hit the telecom company with a 13 billion rupee transfer pricing adjustment. They said the difference in value must have been paid by the parent company, but then loaned back to the parent so that Vodafone India should be reporting continuing interest on the loan. They imputed a 13.5% interest rate. The tax authorities said this added about $490 million to the subsidiary’s income for the two years.
The court said the share subscription was fundamentally a capital contribution that does not give rise to income.
Shell is challenging a transfer pricing adjustment of 152.2 billion rupees ($2.86 billion) with which it was hit after an equity subscription by Shell Gas BV in Holland in shares of Shell India.
CHILE increased taxes on foreign investors under new tax reforms signed into law in late September.
Chile taxes companies currently at a 20% rate, and there is a further 35% tax on dividends at the shareholder level. However, the shareholder receives a credit for the corporate-level tax paid, so the net additional tax is 15%.
Under the original version of tax reform proposed by the government, foreign shareholders would have had to pay tax on their shares of income at the corporate level without waiting for the income to be distributed. The business community objected. A compromise was worked out in the Chilean Congress under which shareholders have the option of paying taxes on their shares of corporate earnings as the income accrues, rather than waiting for it to be distributed. However, anyone who waits until actual distribution to pay tax will pay more. The tax at the corporate level will rise to 27% by 2018 and shareholders would be allowed a credit for only 65% of the corporatelevel tax. This would bring the total tax to 44.5%, with 17.5% of it paid by the shareholder after crediting the corporate-level tax.
On the other hand, if the shareholder pays tax on an accrual basis, then the combined rate would remain at 35%. The corporate-level tax would rise to 25% in 2018, and the shareholder would pay an additional 10% rather than 15%.
Shareholders in countries with tax treaties with Chile would not be subject to the 65% cap on the corporate-level taxes that could be credited. Chile has 26 tax treaties, including with Canada, Portugal, Spain, Switzerland and the United Kingdom.
The lower house of the Chilean Congress ratified a tax treaty with the United States in late September. The upper house must still act. Ratification of the treaty by the US Senate has been blocked by Senator Rand Paul (R-Kentucky), who objects to provisions in it and four other treaties permitting the sharing of information between tax authorities in the US and the other countries.
The treaty has been awaiting ratification since 2010. It would limit withholding taxes on dividends paid cross border to 5% where the shareholder receiving the dividends owns at least 10% of the stock of the company paying the dividends. Otherwise, the limit would be 15%. Withholding taxes on interest would be capped at 4% if the interest is received by a bank or the interest is on a purchase money note in connection with an installment sale of equipment or machinery.
VALUE-OF-SOLAR tariffs in two US states may be addressed by the IRS.
A homeowner in Austin, Texas sent the agency a letter in late September to ask whether he can claim a federal tax credit on a solar system he installs on his roof if he sells the entire electricity output to the local utility in exchange for credits that he can use against his utility bill.
Homeowners in the United States can claim a federal tax credit for 30% of the system cost for rooftop solar systems installed through December 2016. The electricity must be put to personal use. That is not true in this case at least in form. The homeowner also asked the IRS whether the credits he receives for the electricity must be reported as income from the sale of electricity.
Forty-three states and the District of Columbia allow homeowners with rooftop solar systems to sell the excess electricity produced above what the homeowners use themselves back to the local utility through “net metering” where the utility meter runs backwards. Some utilities complain that they end up paying for such electricity at the retail rate rather than the wholesale rate they would have to pay to buy the same electricity in the broader market.
Austin, Texas and Minnesota are moving away from retail rates for net metering to a price that attempts to value the solar electricity by taking into account the costs of operating the grid as well as societal benefits like reduced carbon emissions. Under both programs, a homeowner sells all his electricity to the grid at the value-of-solar tariff and buys back what he needs at the retail rate. In Austin, the homeowner receives nontransferable credits to use against his utility bill. Austin has already implemented the program. Minnesota approved the practice in 2012, but it is not yet in use. The value of solar rate in Austin is currently 10.7¢ a KWh and is recalculated annually according to a formula.
Current retail rates are 1.8¢ to 11.4¢ depending on the pricing tier.
The Austin homeowner who sent the IRS the letter asked the IRS to issue an “information letter” addressing the tax consequences of valueof- solar tariffs.
It is not clear an information letter would give the homeowner what he wants. An information letter is a statement issued by the IRS national office or a district office that “calls attention to a well-established interpretation or principle of tax law . . . without applying it to a specific set of facts.”
Rooftop solar companies are no fans of the value-of-solar movement. Some utilities are also wary of it.
Advocates of such programs say there is no difference in substance between the programs and more traditional net metering. The form as a sale and repurchase is just an accounting device to calculate the net amount the utility should credit the homeowner for the electricity that actually reaches the grid.
However, the IRS may have already tied its hands on the issue. It said in a set of questions and answers about residential solar credits last year that any homeowner selling more than a minimal amount of electricity to the local utility through net metering must reduce his residential solar tax credit on the system by the fraction of total output that will end up being sold to the utility. It suggested the homeowner should be able to claim a 30% investment tax credit instead on the fraction of the solar system that does not qualify for the residential credit since that part of the system would be considered put to business use. The IRS position is in Notice 2013-70 at Q&A27.
Once the decision is made that electricity is being sold, then the conclusion that the credits are income to the homeowner would seem to follow, since they are consideration for the sale. Value-of-solar advocates might do better to change the form.
SOLAR POLE MOUNTS qualify for tax credits as part of a solar system, the IRS said.
The IRS made the statement in a private letter ruling that it made public in late October. The ruling is Private Letter Ruling 201444025.
The ruling was issued to a company that designs and sells solar panels that are mounted on poles, but it retains some to own and operate itself. The poles are of varying heights. The electricity produced powers equipment like lights and speed cameras. There is a base that holds the pole firmly in place. There may also be special doors at the base that lock for security reasons. The poles are sized for the solar panels, and are not suitable for use other than supporting the panels.
A 30% investment tax credit can be claimed on “equipment which uses solar energy to generate electricity.” The IRS said the panels, battery, control equipment, conversion equipment and wiring all qualify and the pole does as well because it is “essential to the functioning of this equipment.”
However, the IRS said, the company must allocate part of the cost to any lights, surveillance equipment, motion detectors, two-way transmission systems and other attachments that protect such equipment from foul weather. These items are not used to generate electricity and do not qualify for a tax credit.
Separately, IRS officials in Washington are concerned that some taxpayers installing solar systems are replacing the roof at the same time and may be improperly claiming a federal tax credit on the cost of the roof replacement. This is of particular concern where the solar panels or tiles double as the roof. The IRS says the taxpayer must back out of tax basis for the credit what it would cost solely to replace the roof without also installing solar panels.
ROOFTOP SOLAR draws more utilities.
The Arizona Corporation Commission is expected to decide by year end whether to allow Arizona Public Service, the state’s largest utility, to lease space on approximately 3,000 customer roofs to install 20 megawatts of solar systems that the utility would own and put in rate base.
The utility would give the customers credits of $30 a month to use against their utility bills. Each lease would run 20 years. The credit amount would not be adjusted for inflation.
The Arizona Corporation Commission staff recommended in early November that the commission reject the proposal.
Rooftop solar companies argue that such proposals are an effort to prevent competition for retail electricity supply in utility service territories and the utlities have an unfair advantage. Utilities already have a leg up in any competition through existing customer relationships and infrastructure. The ability to put systems into rate base would guarantee utilities the ability to recover their costs plus a return through the rates charged all utility customers. Utilities argue that customers would prefer to deal with a company that they know has staying power rather than with newer solar companies that they worry may not be around for the full term of a contract.
Meanwhile, Tucson Electric Power proposed separately that it be allowed to put solar systems on customer roofs and then charge the customers a fixed monthly charge for 25 years for use of the systems.
In South Carolina, Governor Nikki Haley (R) signed a bill over the summer that would let utilities lease solar systems to customers, but they cannot put the systems into rate base. They would have to own the systems through non-regulated affiliates.
Solar companies are watching to see whether a bill the Washington state legislature rejected this year will be reintroduced in 2015. The bill would have given any utility that wants to enter the solar leasing business a monopoly over the leasing of solar systems in its service territory.
In Utah, the Public Service Commission rejected a request by Rocky Mountain Power in late August to charge customers who feed excess electricity from rooftop solar systems into the grid through net metering a backup charge of $4.65 a month. The commission said the utility failed to prove that the charge was “just and reasonable,” but said it was open to revisiting the issue in the future if the utility could produce more data. In the meantime, it approved a 1.9% rate increase on all customers. There are about 2,700 customers in the utility’s service territory who use net metering.
NORTH CAROLINA issued guidelines in October for state tax credits for investing in renewable energy equipment.
The state allows a 35% tax credit to be claimed on new solar, wind, geothermal, biomass, hydroelectric and combined heat and power equipment. It is available for equipment placed in service through 2015. The credit is claimed entirely in the year the equipment is put in service if the equipment is put to personal use. It is claimed ratably over five years if the equipment is put to business use.
A homeowner with a rooftop solar system who sells all of its output to the local utility and buys back what it needs is putting the system to business use.
The credit belongs to the person who put the equipment in service. However, if the equipment is leased, then either the lessor or the lessee may claim the credit. It belongs in the first instance to the lessor, but the lessor can pass it through to the lessee by providing the lessee a “written certification that the lessor will not claim the credit.” It does not matter whether the lease is a capital lease or an operating lease.
The state has issued several rulings about strategies for transferring tax credits. These rulings are private. However, leases are the preferred structure. The tax credit is claimed by a partnership of a state tax equity investor and developer that then leases the project in form immediately after placing it in service to a separate partnership of a federal tax equity investor and the developer. The “lease” is treated as an installment sale of the project to the lessee for federal income tax purposes. The North Carolina Department of Revenue put in the guidance what it has said in rulings so that it will not have to keep answering the same questions.
The tax credit is 35% of the cost of the equipment. If a lessee claims the credit, then the “cost” is eight times the annual rent, unless the lessor claims a federal investment tax credit or Treasury cash grant on the equipment, in which case the credit is calculated by the lessee on the lessor’s cost or possibly on the fair market value of the equipment. The state expert on the credit is unsure whether fair market value can be used, but says the state follows the federal basis rules. Under the federal rules, the lessee calculates its credit on the fair market value. In all other cases, “cost” means cost.
The cost must be reduced to the extent the equipment was paid for partly with public funds. However, there is no reduction on account of having received a Treasury cash grant.
The credit cannot be used to offset more than 50% of tax liability in a year. Unused credits can be carried forward up to five years. There is no recapture of the credit if the equipment is sold, destroyed, retired from service or moved out of state. However, any remaining installments of the tax credit could not be claimed. (Vested, but unused, credits can still be carried forward.) Equipment will be presumed to have been taken out of service if it is shut down for repairs and the repairs do not start within 60 days. A “detailed” explanation must be sent to the state tax authorities to avoid the presumption.
Suppose a partnership places a project in service for business use, the first installment of the tax credit is claimed by partners A and B and then B sells his interest in year 2 to C. A and C can continue sharing in the remaining installments of the tax credit unless the sale of B’s interest causes the partnership to terminate for federal income tax purposes. The state views the credit as belonging to the partnership. If the partnership terminates, then it no longer exists. The credit can be claimed on improvements to an existing project, but only if they increase the generating capacity. If the improvements are entirely new equipment, then a credit can be claimed on the full cost. If the improvements replace other equipment on which a credit was already claimed, then only a fraction of the replacement equipment qualifies. The fraction is the increase in capacity divided by the capacity after the replacement. Thus, for example, if the capacity of an existing solar facility is increased from 50 to 55 megawatts by replacing some of the equipment, and a credit was already claimed on the project, then the credit on the improvements is on 5/55ths of the cost.
No credit can be claimed on a battery added to an existing solar system since it does not increase the capacity.
The amount of credit is capped. Only $2.5 million may be claimed “per installation” for equipment put to business use. The cap is $10,500 “per installation” for equipment put to personal use. These are the limits for solar equipment used to generate electricity and wind, biomass and combined heat and power equipment. An “installation” is equipment that “standing alone or in combination with other machinery, equipment, or real property, is able to produce usable energy on its own.” Each separate array at a solar facility is treated as a separate installation, even though all the electricity passes through a single step-up transformer, as long as there is a disconnect switch allowing each array to be shut down and the array has its own inverter. The North Carolina Department of Revenue said, “Each individual solar energy system should include at least a PV array and an inverter.”
Monitoring equipment can qualify as part of a solar facility, but only up to 5% of the cost of the complete solar system. A battery can be included in the cost of a facility, but only up to 35 KWh of storage capacity per kilowatt of PV capacity (DC rated). If equipment serves two or more functions, such as doubling as the roof or siding, then the “cost” for calculating the tax credit must be reduced by the cost of a comparable product for the non-solar function.
A fuel cell that runs solely on gas qualifies potentially as a combined heat and power system, but only if it qualifies for a federal investment tax credit as a CHP system. If the fuel cell runs on biomass or biomass and gas, then it may qualify as biomass equipment, but there is a reduction in the credit in that case to the extent there is co-firing with gas.
ECONOMIC SUBSTANCE may be lacking.
The IRS warned in October that it remains free to pick apart transactions with more than one leg to deny tax benefits on any leg that is tax motivated while allowing the rest of the transaction to stand. It said it is not limited to accepting or rejecting the transaction as a whole.
The IRS warning is in Notice 2014-58.
The IRS had already used this approach successfully before the warning. (For example, see the April 2013 NewsWire starting on page 31.)
The economic substance doctrine is one of several tools the IRS has available to attack transactions that it considers to be little more than a play for tax benefits. Congress wrote the doctrine into the US tax code in 2010. The doctrine as codified requires a transaction to change the taxpayer’s economic position in a meaningful way and for the taxpayer to have a substantial business purpose, other than federal income tax effects, for entering into the transaction.
The IRS warned that “[w]hen a series of steps include[s] a tax-motivated step that is not necessary to achieve a non-tax objective,” the government may deny tax benefits on the “tax-motivated steps that are not necessary to accomplish the non-tax goals.” It said the tax-motivated steps could take many forms, including interposing an intermediate entity whose involvement is unnecessary to achieve the real or purported business objective.
NO REAL PARTNERSHIP was created, a US appeals court said.
Dow Chemical did two partnership transactions with foreign banks that used a financial product developed by Goldman Sachs called SLIPs, for special limited investment partnerships.
The transactions allowed Dow to claim large deductions on assets that had already depreciated.
Dow identified assets with a high value but zero or little tax basis, contributed them to a partnership and brought in foreign banks as limited partners. Each partnership lasted about five years.
In the first deal, Dow had its subsidiaries contribute 73 patents worth $867 million. Dow had a zero tax basis in 71 of the patents. It also contributed $110 million in cash and a shell corporation.
Five foreign banks contributed $200 million for the limited partner interests. The partnership was owned 18% by the foreign banks.
Dow continued to use the patents and paid royalties to the partnership that were not tied to the patent use. It indemnified the banks against any liabilities tied to the assets or taxes.
The partnership — called Chemtech I — operated from April 1993 through June 1998. The Dow royalty payments were its main source of income. The banks received 99% of profits until the profits reached a 6.947% priority return plus a relatively small distribution to cover Swiss tax liability, since the partnership was considered to be managed from Switzerland.
The partnership contributed the remaining cash from the Dow royalty payments to the shell corporation, which lent most of it back to Dow. If profits fell short of the priority return, then the partnership still had to pay the banks 97% of their priority return.
Here are numbers for 1994 as an illustration. Dow paid deductible royalties of $143.3 million. The partnership distributed $13.9 million to the banks. It contributed $136.9 million to the shell corporation that the shell corporation lent back to Dow. The partnership had taxable income of $122.4 million. It allocated $115 million of this income to the banks and $28.1 million to Dow.
The partnership agreement listed 23 things that could cause the partnership to terminate. Many were typical of default triggers in loan agreements. Upon termination, the banks would receive the balance in their capital accounts plus 1% of any gain or less 1% of any loss resulting from any change in the partnership’s asset value. The banks were compensated for any shortfall in their expected return if the partnership terminated before seven years.
Dow terminated the partnership in February 1998 because of new US tax regulations that could subject the banks to 30% withholding taxes.
Dow would have had to indemnify them for the withholding taxes. The banks were repaid their capital account balances plus 1% of the increase in value of the patents.
Dow then formed a new partnership to do the same thing. It contributed a chemical plant in Louisiana worth $715 million but with a tax basis of $18.5 million. The new partnership leased the plant to Dow. Dow paid rent. A US affiliate of Rabobank contributed $200 million in June 1998 as limited partner in exchange for a 20.45% interest. The bank had a 6.375% priority return and could terminate the partnership after roughly five years.
In March 2003, the bank and Dow negotiated a new partnership agreement that reduced the bank’s priority return to 4.207%. The partnership continued to operate under the new terms for roughly another five years through June 2008.
A federal district court said no real partnerships were formed between Dow and the banks. In reality, the banks made loans to Dow.
A US appeals court agreed in September that no partnerships were formed. It rejected Dow’s argument that it first had to decide whether the banks were lenders or partners. Dow said they could not be lenders because there was no fixed maturity for repayment of their investments.
The court said the following persuaded it that no real partnerships were formed. The banks earned a fixed annual return regardless of the success of the underlying business. They had only a 1% interest in any appreciation in asset value. They took virtually no risk tied to the patents or the chemical plant. Dow indemnified the banks for any liabilities tied to the patents or chemical plant and for any tax liability.
Various steps were taken to eliminate what little risk there was, such as requiring each partnership to hold collateral worth 3.5 times the unrecovered capital contributions of the banks. If the banks perceived any risk, they could terminate the partnership and get their money back. For example, they could terminate if the partnership failed to distribute at least 97% of the expected preferred return each quarter.
The bottom line, the court said, is there was no intention to join together to form a real business with a sharing of profits from that business. The assets were assembled with tax attributes in mind and, in the case of the patents, did not include all the rights that any licensee would need to function as a real business. The banks had downside protection and virtually no upside.
The case is Chemical Royalty Associates, L.P. v. United States. Dow said it was disappointed by the decision and is evaluating its options.
ARGENTINA addressed a VAT issue.
The Supreme Court held in September that the base for calculating value added taxes on payments to foreign suppliers includes any tax gross up to cover income taxes on fees paid to the foreign supplier.
Puentes del Litoral holds a concession to build a toll road between two cities, Rosario and Victoria. It made payments under services agreements with foreign companies who provided the know-how. The foreign companies submitted separate invoices for gross ups for Argentine income taxes on the service fees. The general VAT rate in Argentina is 21%. VAT applies to fees for services.
The Argentine tax authorities take the position that VAT must be paid on tax gross ups because the gross ups are part of the cost of the services. The Supreme Court agreed. The Federal Tax Court had been split on the issue: two of the four “chambers” agreed with the tax authorities and two did not.
VAT is paid by the Argentine company receiving the services.
COLOMBIA removed the Cayman Islands, British Virgin Islands and Bermuda from a list of tax havens.
Forty-one jurisdictions remain on the list. The remaining jurisdictions can be removed by entering into agreements to share information with the Colombian tax authorities. Payments that Colombian companies make to suppliers in tax havens are subject to a 33% withholding tax. The payor must collect the tax. If he does not, then he cannot deduct the payments for Colombian tax purposes.
Many Latin American countries have some form of tax haven blacklist.
INDIANA does not tax out-of-state investors if the investment is structured properly.
Vodafone had a 45% interest as a general partner in a Delaware general partnership with Verizon Wireless through which the two companies provided cell phone services.
States tax income that is earned in the state. Vodafone treated its share of income from the partnership as earned in Indiana, but then thought better of it and asked for a refund of the taxes it paid during the period 2005 through 2008. The company argued that the income was from an intangible asset — its partnership interest — and companies only have to pay taxes on income from intangibles if they are domiciled in the state.
It lost in court. The Indiana Tax Court said in June 2013 that the income was income from an operating business. “[T]he mere fact that Vodafone was a partner in a general partnership gives its income from that partnership the character of operational income.” The fact that Vodafone had only a minority interest was not enough to change the character of the income; as general partner, it was not merely a passive investor.
Vodafone appealed, but the parties told the court this summer that they reached a settlement under which the Indiana Tax Court decision will stand. The appeal was withdrawn. The case is Vodafone Americas Inc. v. Department of State Revenue. The court order dismissing the appeal did not surface until October.
Indiana does not tax income that the owner of a minority interest in a limited liability company receives as a passive investor.
SOUTH CAROLINA said that generating electricity is “manufacturing.”
The decision, in a case involving Duke Energy, affects what share of income Duke must treat as earned in South Carolina. Duke operates in more than one state. Manufacturers must allocate income to South Carolina based on the share of total property, payroll and sales the manufacturer has in the state. If Duke were not a manufacturer, then it would allocate based solely on the share of total sales in South Carolina.
Duke said it overpaid income taxes in South Carolina for the period 1978 through 2001 by $126.2 million because it incorrectly calculated the amount of income it earned in the state. It assumed it was a manufacturer.
The state tax department said Duke’s calculations were correct and refused to refund the money. Duke lost two rounds in the South Carolina courts, most recently in the court of appeals.
The court said that while “manufacturing” is not defined in the state tax code, electricity generation is manufacturing under the “plain and ordinarily meaning of the word” since it creates an electrical charge that did not exist previously. The state Supreme Court ruled in 1926, and again in 1930 in a case involving Duke, that electricity generation is manufacturing. Duke argued that the Supreme Court decisions were stale and decided in other contexts. The appeals court disagreed.
The case is Duke Energy Corporation v. South Carolina Department of Revenue. The court of appeals released its decision in the case on October 8. Duke asked the court on October 22 for a rehearing.
PILOT PAYMENTS can be deducted as property taxes, the IRS said.
“PILOT” stands for payments in lieu of taxes. Developers in some states arrange for a county or state agency to hold title to a project as a way to reduce sales and property taxes. Equipment purchased by a state or county agency is usually exempted from sales taxes, and property owned by the agency is not subject to property tax. The developer negotiates payments in lieu of property taxes that are a fraction of the property taxes it would otherwise have had to pay.
US taxpayers can deduct property taxes.
A condominium association asked the IRS for a ruling that PILOT payments are a form of property tax that can be deducted. The association owns a condominium building on land that a not-for-profit corporation leases from a state development authority and then subleases to the association. The association makes PILOT payments to the not-for-profit corporation which makes them, in turn, to the state development authority. Each condominium owner pays his share of the PILOT payments.
The IRS said payments qualify as a tax if they satisfy three tests. These do. The payments must be measured by or equal to amounts imposed by regular taxing statutes. They must be imposed by a specific state statute. The proceeds must be designated for a public purpose rather than for some privilege, service or regulatory function, or for some other local benefit tending to increase the value of the property upon which the payments are made.
In this case, state law exempts land owned by the state development authority from taxes, but requires the authority to collect PILOT payments and use the payments either to improve or maintain the property involved or transfer them to the general fund of the city for general public purposes.
The IRS analysis is in Private Letter Ruling 201442020. The agency made the ruling public in October.
MICHIGAN utilities do not have to pay sales and use taxes on new equipment that they will use to distribute electricity and gas.
The sales and use tax rate in Michigan is 6%.
Sales taxes are collected on sales of equipment in state. Use taxes are collected on equipment bought out of state and brought into the state for use in Michigan.
A Michigan appeals court ruled in October that equipment used to distribute electricity or gas is exempted from taxes under an “industrial processing exemption.” The exemption applies to equipment that will be used to convert or condition “tangible personal property” for use in manufacturing a product that will ultimately be sold at retail. The court said electricity and gas are tangible. The utility sells them to retail customers. The issue, it said, is whether the utility converts or conditions electricity or gas in the process of distributing it to customers. The court said it does.
It said the utility had to prove that it changes the “form, composition, quality, combination, or character” of the electricity or gas while moving it to consumers. The utility presented exhaustive evidence, the court said, that the electricity and gas are not safe or usable when they first enter the distribution lines or pipes. They are converted on the way to consumers.
The case is Consumers Energy Company v. Department of Treasury. The Michigan Department of Treasury had tried to collect $21.2 million in taxes from Consumers Energy after an audit of the period October 1997 through December 2004. The court reached the same conclusion in an earlier case involving Detroit Edison.
THE US ENVIRONMENTAL Protection Agency released additional thoughts for comment in late October on some of the more controversial aspects of its June plan to reduce carbon dioxide emissions from existing power plants that use fossil fuels.
Comments are due by December 1, 2014, a date that may be challenging for some states that had closely-contested governors’ races. The June plan set individual state goals for reducing carbon dioxide emissions (expressed in lbs CO2/MWh) and listed measures states could use to cut emissions.
The June plan also suggested that states could convert these goals expressed in emissions per megawatt hour into tons of CO2 emissions per year, which would be easier to implement for states that develop or enter into cap-and-trade programs.
Although the ultimate targets in the June plan would not need to be achieved until 2030, there are interim targets to take stock of how states are doing in 2020. EPA suggested use of the following four measures (also termed “building blocks”) to reach the emissions targets: improved heat rates at coal-fired power plants, increased use of low-emitting power sources like natural gas, increased use of zero- and low-emitting power sources like solar energy and increased demand-side energy efficiency. EPA is required to finalize the plan by June 1, 2015.
Critics of the plan complain that meeting the 2020 interim targets does not allow states enough flexibility to choose how best to cut emissions. The plan also appeared to assume that some states could readily increase the use of combined-cycle natural gas-fired power plants by dispatching those power plants up to about a 70% capacity factor. EPA is now suggesting that states could count early reductions for puposes of demonstrating compliance with the 2020 targets. Such reductions may be in the form of energy efficiency programs implemented before 2020 and would give states more time to phase in other reduction measures. EPA is also suggesting phasing in improvements of heat rates at coal-fired power plants and increases in the dispatch rates of natural gas-fired power plants.
The agency also passed along in October some suggestions that some people who commented on the June plan made for how states might incorporate the use of new natural gas-fired power plants and co-firing of natural gas in existing coal-fired boilers to meet the required emissions targets. EPA said it might also look at the regional availability of renewable energy to set state renewable energy targets.
The emissions goals set in the June plan were based on 2012 power sector data. Some have suggested that this baseline may not have been representative, so the agency released data for years 2010 and 2011 and is taking comments on whether state emissions targets should be based on an average of several years of information.
The US Department of Energy reported in late September that the price of solar rooftop systems in the United States fell 12% to 19% in 2013. Another drop of 3% to 12% is expected in 2014 . . . . The top 10 US wind companies and their market shares as of the end of Q2 2014 were NextEra 20.07%, Iberdrola Renewables 10.48%, EDP Renewables 7.07%, E.On 6.49%, Invenergy 5.74%, NRG Energy 4.11%, EDF Renewable Energy 3.57%, Duke 3.48%, BP 3.09% and Enel 3.05%, according to Platts. The top 10 account for 67% of the market. There were 78 US wind companies making wholesale electricity sales.